AMERICAN ELECTRIC POWER CO INC

(c)Cooling degree days are calculated on a 70 degree temperature base.

•Retail Revenues increased $5 million primarily due to the following:

•A $25 million increase in revenue from rate riders.

•A $12 million decrease in weather-related usage primarily due to a 15% decrease in cooling degree days.

•An $8 million decrease in weather-normalized revenues primarily in the residential class.

•Transmission Revenues increased $16 million due to the following:

•A $10 million increase in interim rates driven by increased transmission investments.

•A $6 million increase due to increased load.

•Other Operation and Maintenance expenses increased $8 million primarily due to the following:

•A $4 million increase in distribution-related expenses.

•A $4 million increase in employee-related expenses.

•Interest Expense increased $8 million primarily due to higher debt balances and interest rates.

The major components of the increase in revenues were as follows:

•Retail Revenues increased $85 million primarily due to the following:

•A $73 million increase in revenue from rate riders.

•A $21 million increase in weather-normalized revenues primarily in the commercial and residential classes.

•A $10 million decrease in weather-related usage primarily due to a 5% decrease in cooling degree days.

•Transmission Revenues increased $47 million due to the following:

•A $29 million increase in interim rates driven by increased transmission investments.

•An $18 million increase due to increased load.

•Other Operation and Maintenance expenses increased $49 million primarily due to the following:

•A $28 million increase due to a prior year decrease in expenses driven by legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered.

•A $20 million increase in employee-related expenses due to the voluntary severance program.

•Depreciation and Amortization expenses increased $17 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes decreased $12 million primarily due to lower property taxes driven by decreased tax rates.

•Allowance for Equity Funds Used During Construction increased$15 million primarily due to a higher AFUDC base.

•Interest Expense increased $15 million primarily due to the following:

•A $21 million increase due to higher debt balances and interest rates.

•A $6 million decrease due to an increase of capitalization of AFUDC on prepaid pension and OPEB.

•Income Tax Expense increased $20 million primarilydue to the following:

•A $16 million increase due to an increase in pretax book income.

•A $6 million increase due to a decrease in amortization of Excess ADIT.

ASSETS

Summary of Investment in Transmission Assets for AEPTCo

•Transmission Revenues increased $35 million primarily due to continued investment in transmission assets.

•Depreciation and Amortization expenses increased $9 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $6 million primarily due to higher property taxes driven by increased transmission investment.

•Income Tax Expense increased $8 million primarily due to an increase in pretax book income and an increase in state income taxes.

•Transmission Revenues increased $106 million primarily due to continued investment in transmission assets.

•Other Operation and Maintenance expenses increased $16 million primarily due to a $12 million increase in employee-related expenses driven by an $11 million increase associated with the voluntary severance program.

•Depreciation and Amortization expenses increased $30 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $12 million primarily due to higher property taxes driven by increased transmission investment.

•Interest Expense increased $13 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $11 million primarily due to an increase in pretax book income.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

ASSETS

LIABILITIES AND MEMBER’S EQUITY

•Retail Revenues increased $66 million primarily due to the following:

•A $28 million increase in rider revenues.

•A $23 million increase in rates due to the 2020-2022 Virginia Triennial Review.

•A $7 million increase in weather-related usage driven by a 10% increase in cooling degree days.

•A $6 million increase in fuel revenues.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $15 million primarily due to expensing of past under-recovered fuel deferrals in West Virginia to correspond with recovery of those deferrals in ENEC rates.

•Other Operation and Maintenance expenses increased $28 million primarily due to the following:

•A $13 million increasedue to prior year proceeds received for insurance policy settlements.

•An $11 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $7 million increase in distribution expenses primarily due to an increase in vegetation management costs.

•A $7 million decrease due to the January 2024 completion of regulatory asset amortization related to under-earnings during the 2017-2019 Triennial Review.

•Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base.

•Retail Revenues increased $244 million primarily due to the following:

•An $88 million increase in rider revenues.

•A $60 million increase in rates due to the 2020-2022 Virginia Triennial Review.

•A $57 million increase in fuel revenues.

•A $47 million increase in weather-related usage driven by a 36% increase in cooling degree days and an 11% increase in heating degree days.

•Other Revenues increased $11 million primarily due to pole attachment revenue.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $99 million primarily due to expensing of past under-recovered fuel deferrals in West Virginia to correspond with recovery of those deferrals in ENEC rates, increased non-recoverable wind purchases and the amortization of Excess ADIT through the ENEC.

•Other Operation and Maintenance expenses increased $81 million primarily due to the following:

•A $49 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $26 million increase in employee-related expensesdue to the voluntary severance program.

•A $16 million increase indistribution expenses primarily due to an increase in vegetation management costs.

•A $13 million increasedue to prior year proceeds received for insurance policy settlements.

•A $19 million decrease due to the January 2024 completion of regulatory asset amortization related to under-earnings during the 2017-2019 Triennial Review.

•Depreciation and Amortization expenses increased $20 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $6 million due to an increase in Virginia state minimum taxes.

•Income Tax Expense decreased $10 million primarily due to an increase in amortization of Excess ADIT.

ASSETS

•Retail Revenues increased $32 million primarily due to the following:

•A $31 million increase in weather-normalized margins in all customer classes.

•A $15 million increase in rider revenues.

•A $9 million increase in weather-related usage primarily due to an 18% increase in cooling degree days.

•A $7 million increase due to the implementation of new base rates in Indiana and Michigan.

•A $12 million decrease due to regulatory provisions for refund.

•A $12 million decrease in fuel revenues primarily driven by lower fuel rates in Indiana.

•Off-system Sales increased $25 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $11 million primarily due to decreased recoverable fuel costs and a decrease due to a regulatory true-up associated with a final commission order, partially offset by an increase in merchant generation at Rockport Plant and an increase in recoverable purchased power costs.

•Purchased Electricity from AEP Affiliates increased $6 million primarily due to an increase in purchased electricity from Rockport Plant.

•Other Operation and Maintenance expenses increased $12 million primarily due to an increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•Depreciation and Amortization expenses increased $16 million primarily due to an increase in regulatory reserves related to Nuclear PTCs.

•Income Tax Expense decreased $55 million primarily due to a $61 million decrease related to estimated Nuclear PTCs.

•Retail Revenues increased $21 million primarily due to the following:

•A $22 million increase in weather-related usage primarily due to a 34% increase in cooling degree days.

•An $18 million increase in weather-normalized margins in the residential and commercial classes.

•A $12 million increase due to the implementation of new base rates in Indiana and Michigan.

•A $9 million increase in rider revenues.

•A $34 million decrease due to regulatory provisions for refund.

•A $10 million decrease in fuel revenues primarily driven by lower fuel rates in Indiana.

•Off-system Sales increased $26 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.

•Transmission Revenues increased $10 million primarily due to continued investment in transmission assets.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $5 million primarily due to an increase in merchant generation at Rockport Plant, partially offset by decreased recoverable fuel costs.

•Purchased Electricity from AEP Affiliates increased $30 million primarily due to an increase in purchased electricity from Rockport Plant.

•Other Operation and Maintenance expenses increased $41 million primarily due to the following:

•A $23 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $15 million increase in employee-related expenses due to the voluntary severance program.

•An $8 million increase in non-utility operation expenses due to an increase in RTD expenses and merchant operation expenses at Rockport Plant.

•A $4 million decrease in distribution expenses primarily due to a decrease in vegetation management costs.

•A $4 million decrease in nuclear expenses at Cook Plant primarily due to lower refueling outage expenses.

•A $3 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2024.

•Asset Impairments and Other Related Charges increased $13 million due to the Federal EPA’s revised CCR rules.

•Depreciation and Amortization expenses increased $6 million primarily due to the following:

•A $13 million increase in regulatory reserves related to Nuclear PTCs.

•A $9 million increase due to a higher depreciable base.

•An $18 million decrease primarily due to the deferral of Excess ADIT as a result of the PLR received regarding the treatment of stand-alone NOLCs and the timing of refunds to customers under rate rider mechanisms.

•Taxes Other Than Income Taxes increased $7 million primarily due to an increase in property taxes resulting from additional capital expenditures.

•Income Tax Expense decreased $132 million primarily due to the following:

•A $67 million decrease due to a reduction in Excess ADIT as a result of the IRS PLR and I&M Michigan jurisdictional treatment of stand-alone NOLCs.

•A $61 million decrease due to estimated Nuclear PTCs.

ASSETS

(dollars in millions)

(a)Represents energy delivered to distribution customers.

(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.

•Retail Revenues increased $4 million primarily due to the following:

•A $105 million increase in revenue from rate riders.

•A $14 million increase in weather-related usage driven by a 35% increase in cooling degree days.

•A $104 million decrease due to lower customer participation in OPCo’s SSO, partially offset by higher prices.

•A $12 million decrease in weather-normalized revenues in the industrial class.

•Other Revenues increased $13 million primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

•Purchased Electricity for Resale expenses decreased $62 million primarily due to the following:

•An $80 million decrease in recoverable auction purchases primarily due to lower volumes driven by lower customer participation in OPCo’s SSO.

•A $19 million increase in recoverable OVEC costs.

•Purchased Electricity from AEP Affiliates expenses decreased $24 million primarily due to decreased recoverable auction purchases in OPCo’s SSO.

•Other Operation and Maintenance expenses increased $50 million primarily due to the following:

•A $31 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•An $11 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•An $8 million increase in distribution expenses primarily related to recoverable storm restoration costs and recoverable vegetation management expenses.

•Retail Revenues increased $6 million primarily due to the following:

•A $279 million increase in revenue from rate riders.

•A $44 million increase in weather-related usage driven by a 56% increase in cooling degree days.

•A $306 million decrease due to lower customer participation in OPCo’s SSO, partially offset by higher prices.

•A $15 million decrease in weather-normalized revenues in the industrial class, partially offset by residential and commercial classes.

•Off-system Sales decreased $12 million primarily due to 2023 PJM settlements related to winter storm Elliott.

•Other Revenues increased $26 million due to the following:

•A $33 million increase due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

•A $9 million decrease in recoverable sales of renewable energy credits.

•Purchased Electricity for Resale expenses decreased $278 million primarily due to the following:

•A $342 million decrease in recoverable auction purchases primarily due to lower volumes driven by lower customer participation in OPCo’s SSO, partially offset by higher prices.

•A $16 million decrease in recoverable alternative energy rider expenses.

•An $81 million increase in recoverable OVEC costs.

•Purchased Electricity from AEP Affiliates expenses increased $37 million primarily due to increased recoverable purchases in OPCo’s SSO auction.

•Other Operation and Maintenance expenses increased $121 million primarily due to the following:

•A $73 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $19 million increase in distribution expenses primarily due to recoverable storm restoration costs and recoverable vegetation management expenses.

•A $16 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•A $15 million increase in employee-related expenses due to the voluntary severance program.

•Asset Impairments and Other Related Charges increased $53 million primarily due to Federal EPA revised CCR rules.

•Depreciation and Amortization expenses increased $69 million primarily due to a higher depreciable base and an increase in recoverable rider depreciable assets.

•Taxes Other Than Income Taxes increased $43 million primarily due to the following:

•A $35 million increase due to higher property taxes driven by additional investments in transmission and distribution assets and tax rate changes.

•An $8 million increase in state excise taxes due to increased billed KWh in 2024 resulting in a higher tax burden.

•Interest Expense increased $13 million primarily due to higher debt balances and interest rates.

•Income Tax Expense decreased $10 million primarily due to a decrease in pretax book income.

ASSETS

(a)Includes municipalities and cooperatives, unit power and other wholesale customers.

(a)Includes firm wholesale sales to municipals and cooperatives.

•Retail Revenues decreased $30 million primarily due to the following:

•A $39 million decrease in fuel revenue primarily due to lower authorized fuel rates.

•A $9 million decrease in weather-related usage primarily due to an 8% decrease in cooling degree days.

•An $11 million increase in weather-normalized margins primarily in the residential class.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $33 million primarily due to the lower current year amortization of under-recovered fuel regulatory assets driven by lower authorized fuel rates.

•Other Operation and Maintenance expenses increased $12 million primarily due to the following:

• A $7 million increase in transmission expenses primarily due to an increase in SPP expenses.

• A $3 million increase in overhead line maintenance expenses.

•Depreciation and Amortization expenses increased $9 million primarily due to a higher depreciable base, implementation of new rates and the amortization of regulatory assets related to NCWF.

•Income Tax Benefit decreased $5 million primarily due to the following:

•A $13 million decrease due to a decrease in amortization of Excess ADIT.

•A $4 million increase due to a decrease in pretax book income.

•A $3 million increase due to a decrease in state income tax.

•Retail Revenues decreased $88 million primarily due to the following:

•A $137 million decrease in fuel revenue primarily due to lower authorized fuel rates.

•A $32 million increase in base rate and rider revenues.

•Other Revenues increased $14 million primarily due to associated business development revenues driven by costs associated with a third-party construction project.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $128 million primarily due to the lower current year amortization of under-recovered fuel regulatory assets driven by lower authorized fuel rates.

•Other Operation and Maintenance expenses increased $44 million primarily due to the following:

•A $16 million increase in transmission expenses primarily due to an increase in SPP expenses.

•A $13 million increase in associated business development expenses primarily due to partially reimbursable development costs associated with a third-party construction project.

•A $10 million increase in employee-related expensesdue to the voluntary severance program.

•Depreciation and Amortization expenses increased $14 million primarily due to a higher depreciable base, implementation of new rates and the amortization of regulatory assets related to NCWF.

•Taxes Other Than Income Taxes increased $11 million primarily due to an increase in property taxes.

•Interest Expense decreased $7 million primarily due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

•Income Tax Benefit increased $45 million primarily due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

CONDENSED STATEMENTS OF INCOME

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

CONDENSED STATEMENTS OF CHANGES IN

CONDENSED BALANCE SHEETS

ASSETS

CONDENSED BALANCE SHEETS

CONDENSED STATEMENTS OF CASH FLOWS

(a)Includes firm wholesale sales to municipals and cooperatives.

•Retail Revenues decreased $27 million primarily due to the following:

•A $13 million decrease infuel revenue.

•A $12 million decrease in weather-normalized margins primarily in the residential and industrial classes.

•A $10 million decrease in weather-related usage primarily due to a 7% decrease in cooling degree days.

•An $8 million increase primarily due to formula rate increases in Arkansas.

•Transmission Revenues increased $7 million primarily due to an increase in transmission investment.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $11 million primarily due to a current year decrease in amortization of under-recovered fuel regulatory assets.

•Depreciation and Amortization expenses increased $17 million primarily due to an increase in amortization of regulatory assets and a higher depreciable base.

•Interest Expense decreased $10 million primarily due to the following:

•An $8 million decrease due to the prior year amortization of carrying charges on storm-related regulatory assets.

•A $3 million decrease due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

•Income Tax Benefit decreased $11 million primarily due to the following:

•A $5 million decrease due to a decrease in PTCs.

•A $4 million decrease due to a decrease in amortization of Excess ADIT.

•Retail Revenues decreased $176 million primarily due to the recognition of a $160 million probable revenue refund associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.

•Transmission Revenues increased $10 million primarily due to a $15 million increase in continued investment in transmission assets and load, partially offset by a $4 million reversal of a prior period provision for refund in 2023.

•Other Revenues increased $5 million primarily due toassociated business development revenues driven by costs associated with a third-party construction project.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $33 million primarily due to a current year decrease in amortization of under-recovered fuel regulatory assets.

•Other Operation and Maintenance expenses increased $48 million primarily due to the following:

•A $17 million increase in employee-related expenses primarily due to the voluntary severance program.

•A $14 million increase due to a disallowance recorded on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.

•An $11 million increase in SPP transmission expenses.

•A $5 million increase due to the prior year capitalization of previously expensed renewable generation pre-construction charges.

•Depreciation and Amortization expenses increased $31 million primarily due to an increase in amortization of regulatory assets and a higher depreciable base, partially offset by the recognition of a regulatory asset related to NOLCs.

•Taxes Other Than Income Taxes decreased $11 million primarily due to a decrease in property taxes.

•Interest Expense decreased $32 million primarily due to the decrease in the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

•Income Tax Benefit increased $163 million primarily due to the following:

•A $109 million increase due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

•A $34 million increase due to a decrease in pretax book income.

•A $32 million increase due to the reversal of a regulatory liability related to the merchant portion of Turk Plant Excess ADIT as a result of the APSC's March 2024 denial of SWEPCo's request to allow the merchant portion of the Turk Plant to serve Arkansas customers.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

ASSETS

LIABILITIES AND EQUITY

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise:

1. SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2024 is not necessarily indicative of results that may be expected for the year ending December 31, 2024. The condensed financial statements are unaudited and should be read in conjunction with the audited 2023 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 26, 2024.

Earnings Per Share (EPS) (Applies to AEP)

Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted-average outstanding common shares, assuming conversion of all potentially dilutive stock awards.

The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:

There were no antidilutive shares outstanding as of September 30, 2024 and 2023, respectively.

Restricted Cash (Applies to AEP, AEP Texas and APCo)

Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds.

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statements of cash flows:

Supplementary Cash Flow Information (Applies to AEP)

2. NEW ACCOUNTING STANDARDS

Management reviews the FASB’s standard-setting process and the SEC’s rulemaking activity to determine the relevance, if any, to the Registrants’ business. The following standards/rules will impact the Registrants’ financial statements.

SEC Climate Disclosure Rule

On March 6, 2024, the SEC adopted final rules that require registrants to disclose certain climate-related information in registration statements and annual reports. The final rules require registrants to disclose, among other things, material climate-related risks, activities to mitigate such risks and information about a registrant’s board of directors oversight and management’s role in managing material climate-related risks. The final rules also require registrants to provide information related to any climate-related targets or goals that are material to a registrant’s business, results of operations or financial condition. A majority of the reporting requirements are applicable to the fiscal year beginning in 2025, with the addition of assurance reporting for GHG emissions starting in 2029 for large accelerated filers. Litigation challenging the new rules was filed by multiple parties in multiple jurisdictions, which have been consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the SEC issued an order staying the final climate disclosure rules pending the completion of judicial review at the Court of Appeals. The Registrants are currently evaluating the impact of the final rules on their respective consolidated financial statements and related disclosures.

ASU 2023-07 “Improvements to Reportable Segment Disclosures” (ASU 2023-07)

In November 2023, the FASB issued ASU 2023-07, to address investors’ observations that there is limited information disclosed about segment expenses and to better understand expense categories and amounts included in segment profit or loss. The new standard requires annual and interim disclosure of (a) the categories and amounts of significant segment expenses (determined by management using both qualitative and quantitative factors) that are regularly provided to the CODM and included within each reported measure of segment profit or loss, (b) the amounts and a qualitative description of “other segment items”, defined as the difference between reported segment revenues less the significant segment expenses and each reported measure of segment profit or loss disclosed, (c) reportable segment profit or loss and assets that are currently only required annually, (d) the CODM’s title and position, and an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources and (e) a requirement that entities with a single reportable segment provide all disclosures required by ASU 2023-07 and all existing segment disclosures in Topic 280. Additionally, this new standard allows disclosure of one or more of additional profit or loss measures if the CODM uses more than one measure provided that at least one of the disclosed measures is determined in a manner “most consistent with the measurement principles under GAAP”. If multiple measures are presented, additional disclosure is required about how the CODM uses each measure to assess performance and decide how to allocate resources.

The amendments in the new standard are effective on a retrospective basis for all entities for fiscal years beginning after December 15, 2023 and interim periods within fiscal periods beginning after December 15, 2024 with early adoption permitted. Management plans to adopt ASU 2023-07 effective for the 2024 10-K.

ASU 2023-09 “Improvements to Income Tax Disclosures” (ASU 2023-09)

In December 2023, the FASB issued ASU 2023-09, to address investors’ suggested enhancements to (a) better understand an entity’s exposure to potential changes in jurisdictional tax legislation and the ensuing risks and opportunities, (b) assess income tax information that affects cash flow forecasts and capital allocation decisions and (c) identify potential opportunities to increase future cash flows.

The new standard requires an annual rate reconciliation disclosure of the following categories regardless of materiality: state and local income tax, net of federal income tax effect, foreign tax effects, effect of changes in tax laws or rates enacted in the current period, effect of cross-border tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items and changes in unrecognized tax benefits.

The new standard also requires an annual disclosure of the amount of income taxes paid (net of refunds received) disaggregated by federal, state and foreign taxes and by individual jurisdictions that are equal to or greater than 5 percent of total income taxes paid. Disclosure of income (loss) from continuing operations before income tax expense (benefit) disaggregated between domestic and foreign jurisdictions and income tax expense (benefit) from continuing operations disaggregated by federal, state and foreign jurisdictions is required.

The new standard removes the requirement to disclose the cumulative amount of each type of temporary difference when a deferred tax liability is not recognized because of the exceptions to comprehensive recognition of deferred taxes related to subsidiaries and corporate joint ventures.

The amendments in the new standard may be applied on either a prospective or retrospective basis for public business entities for fiscal years beginning after December 15, 2024 with early adoption permitted. Management has not yet made a decision to early adopt the amendments to this standard or how to apply them.

ASU 2024-03 “Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures” (ASU 2024-03)

In November 2024, the FASB issued ASU 2024-03, the intent of which is to improve financial reporting and respond to investor input by requiring public business entities to disclose additional information about certain expenses in the notes to financial statements in interim and annual reporting periods. Among other provisions, the new standard requires disclosure of disaggregated amounts for expenses such as employee compensation, depreciation, and intangible asset amortization included in each expense caption presented on the face of the income statement. Public business entities are required to include certain amounts that are already required to be disclosed under GAAP in the same disclosure as the other disaggregation requirements as well as a qualitative description of any amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. The new standard also requires disclosure of the total amount of selling expenses and, in annual reporting periods, an entity’s definition of selling expenses. An entity is not precluded from providing additional voluntary disclosures that may provide investors with additional decision-useful information.

The amendments in the new standard are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The amendments in the new standard should be applied either prospectively to financial statements issued for reporting periods after the effective date or retrospectively to any or all prior periods presented in the financial statements. Management is evaluating the new standard and has not yet determined when, or the method by which, the Registrants will adopt its amendments.

3. COMPREHENSIVE INCOME

The disclosures in this note apply to AEP only. The impact of AOCI is not material to the financial statements of the Registrant Subsidiaries.

Presentation of Comprehensive Income

The following tables provide AEP’s components of changes in AOCI and details of reclassifications from AOCI. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional information.

(a)Amounts reclassified to the referenced line item on the statements of income.

4. RATE MATTERS

As discussed in the 2023 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2023 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2024 and updates the 2023 Annual Report.

Regulated Generating Units (Applies to AEP, PSO and SWEPCo)

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management continuously evaluates cost estimates of complying with these regulations in balance with reliability and other factors, which has resulted in, and in the future may result in, a proposal to retire generating facilities earlier than their currently estimated useful lives.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could reduce future net income and cash flows and impact financial condition.

Regulated Generating Units that have been Retired

SWEPCo

In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 2021. See the “2020 Texas Base Rate Case” section below for additional information. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the prudency of the retirement of the Dolet Hills Power Station and resulted in a disallowance of $14 million in the first quarter of 2024.

In March 2023, the Pirkey Plant was retired. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana jurisdictional share of the Pirkey Plant, through a separate rider, through 2032. As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. In July 2023, Texas ALJs issued a PFD that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the ALJs’ July 2023 PFD. In the open meeting, the commissioners expressed their concerns that the analysis in support of SWEPCo’s decision to retire the Pirkey Plant was not robust enough and that SWEPCo should have re-evaluated the decision following Winter Storm Uri. The treatment of the cost of recovery of the Pirkey Plant is expected to be addressed in a future rate case. As of September 30, 2024, the Texas jurisdictional share of the net book value of the Pirkey Plant was $69 million. To the extent any portion of the Texas jurisdictional share of the net book value of the Pirkey Plant is not recoverable, it could reduce future net income and cash flows and impact financial condition.

Regulated Generating Units to be Retired

PSO

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. As ordered by the OCC, as part of the 2022 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040.

SWEPCo

In November 2020, management announced that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of September 30, 2024, of generating facilities planned for early retirement:

(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.

(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with the removal of Northeastern Plant, Unit 3, after retirement.

(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.

(d)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with the removal of Welsh Plant, Units 1 and 3, after retirement.

(e)Represents projected retirement date of coal assets, units are being evaluated for conversion to natural gas after 2028.

(f)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)

In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station. The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through rate riders. As of September 30, 2024, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $76 million, including materials and supplies, net of cost of removal collected in rates. Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of September 30, 2024, SWEPCo had a net under-recovered fuel balance of $23 million, inclusive of costs related to the Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $35 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of up to $55 million, including denial of recovery of the $35 million deferral, with refunds to customers over five years. In February 2024, an ALJ issued a final recommendation which included a proposed $55 million refund to customers and the denial of recovery of the $35 million deferral. SWEPCo filed a motion to present oral arguments with the LPSC to dispute the ALJ’s recommendations. In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the fuel recovery dispute and resulted in a fuel disallowance of $11 million. The remaining $24 million regulatory asset balance will be recovered over three years with interest.

In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $48 million of Oxbow mine related costs through 2035.

If any of these costs are not recoverable or customer refunds are required, it could reduce future net income and cash flows and impact financial condition.

Pirkey Plant and Related Fuel Operations (Applies to AEP and SWEPCo)

In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or will seek recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of September 30, 2024, SWEPCo’s share of the net investment in the Pirkey Plant was $187 million, including materials and supplies, net of cost of removal. See the “Regulated Generating Units that have been Retired” section above for additional information. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of March 31, 2023, SWEPCo fuel deliveries, including billings of all fixed costs, from Sabine ceased. Additionally, as of September 30, 2024, SWEPCo had a net under-recovered fuel balance of $23 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Remaining operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses.

In July 2023, the LPSC ordered that a separate proceeding be established to review the prudence of the decision to retire the Pirkey Plant, including the costs included in fuel for years starting in 2019 and after. The LPSC established a procedural schedule stating staff and intervenor testimony is due in November 2024 and a hearing is scheduled for March 2025.

In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $33 million of Sabine related fuel costs through 2035.

If any of these costs are not recoverable or customer refunds are required, it could reduce future net income and cash flows and impact financial condition.

Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)